Method for reducing energy and water demands of scrubbing co2 from co2-lean waste gases

ABSTRACT

Methods and systems for reducing greenhouse gas emissions, including producing a waste gas stream comprising form greater than 0 vol % to less than 20 vol %, inclusive, carbon dioxide, pre-concentrating the waste gas stream to increase a concentration of carbon dioxide, producing a concentrated byproduct stream comprising more than 40 vol %, dissolving carbon dioxide contained in the concentrated byproduct stream in water, producing a dissolved byproduct stream and an undissolved byproduct stream, injecting the dissolved byproduct stream or a portion thereof into a reservoir containing mafic rock, and allowing components of the dissolved byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.17/180,119, which is a continuation-in-part of U.S. patent applicationSer. No. 16/505,378 filed Jul. 8, 2019 that claims priority to U.S.Provisional Patent Application Ser. No. 62/830,945 filed on Apr. 8,2019. These applications are incorporated by reference herein.

FIELD OF THE DISCLOSURE

Embodiments of the disclosure relate to carbon capture from various CO₂emission sources, including those lean in carbon dioxide, such as may beproduced at a power generation facility, as well as those rich in carbondioxide, such as may result during hydrogen production. Embodiments ofthe disclosure relate to synergistic hydrogen production and carboncapture. In particular, embodiments of the disclosure relate to hydrogenproduction from fossil fuels with substantially no greenhouse gasemissions due to carbon capture via mafic rock, for example basalts. Inother aspects, embodiments of the disclosure relate to carbon dioxidecapture via mafic rock, for example basalts.

BACKGROUND

Hydrogen or H₂ is an environmentally-friendly fuel which has thepotential to replace greenhouse gas emitting hydrocarbon fuels. Forexample, hydrogen can be used to power fuel cells. Nearly all H₂currently produced, greater than about 95%, is derived fromhydrocarbons, and predominantly from natural gas. Waste CO₂ released tothe atmosphere (between about 7 and 12 tons CO₂ per ton of H₂ produced)partially negates the “clean fuel” benefits of H₂. To mitigate thecarbon footprint of H₂ production, economically-impractical methods andsystems have been proposed for H₂ production combined with capturing,compressing to a liquid, and injecting co-produced CO₂ into deep(greater than about 850 m underground) sedimentary rock reservoirs in aprocess known as carbon capture and storage (“CCS”). However,conventional CCS adds significant cost to an alreadyhighly-energy-consuming H₂ production process, thus rendering thecombined technology unfeasible under current market and regulatoryconditions.

Previously-proposed combinations of H₂ production from hydrocarbons withconventional CCS of CO₂, for example in depleted hydrocarbon reservoirsor saline groundwater aquifers, adds significant costs associated withpurification, compression, transportation, and injection of CO₂. Anumber of energy-consuming steps are employed to ensure high purity ofCO₂ (greater than about 98 mol %) needed to meet the requirements ofconventional CCS. And, since standard pressure swing adsorption (“PSA”)H₂—CO₂ separation technology alone does not produce CO₂ of sufficientquality and purity for CCS, further purification involving acid gasabsorbing reagents, such as Selexol™ (for heavy and solid hydrocarbons)and methyl diethanolamine (MDEA), is needed.

Safe and economic transportation, as well as the injection and long-termstorage of CO₂ in conventional CCS, depends upon CO₂ being compressed toa supercritical (liquid) state, which also adds significant cost.Consequently, underground CO₂ storage reservoirs must be located atleast about 850 vertical meters below the ground surface to ensure thatthere is sufficient pressure to keep CO₂ in a liquid state, thus addingto the cost of the injection and disposal wells.

Since CO₂ in conventional CCS could remain in a liquid and/or compressedgas state for hundreds or thousands of years, sophisticated long-termmonitoring programs are needed to ensure that CO₂ is truly confined to agiven CCS reservoir and does not migrate to overlying aquifers or thesurface.

Similar to that described above, WO2020/234464 describes a process ofobtaining very pure CO₂ and/or H₂S, pressurizing the CO₂ and/or H₂S,pumping the pressurized CO₂ and/or H₂S and pressurized water downhole,dissolving the pressurized CO₂ and/or H₂S and pressurized water withinthe wellbore, and trapping the mixture in the formation. As thepressurized gases and water are pumped downhole before being broughtinto contact with each other, such processes assume that all the gasesare dissolved in the water. Indeed, in a relatively short time period,i.e., less than a couple of years, all of the CO₂ is dissolved andtrapped in the formation. The process of separating and purification ofthe CO₂ prior to injection is very costly.

SUMMARY OF THE CLAIMED EMBODIMENTS

The present disclosure presents systems and methods for efficient carboncapture. In some embodiments, embodiments relate to production ofhydrogen from hydrocarbon fossil fuels with little to no greenhouse gasemissions. In some embodiments, the first step of the method isco-production of H₂ and waste or byproduct CO₂ from gaseous, liquid, orsolid hydrocarbons (for example steam reforming of natural gas). Theco-production of H₂ and CO₂ from hydrocarbons can be accomplished invarious processes. In a second step of the method, CO₂ is injected intoreactive mafic or ultramafic rocks, where CO₂ and/or other waste gasesare permanently immobilized as precipitated carbonate minerals. The termmafic generally describes a silicate mineral or igneous rock that isrich in magnesium and iron. Mafic minerals can be dark in color, androck-forming mafic minerals include olivine, pyroxene, amphibole, andbiotite. Mafic rocks include basalt, diabase, and gabbro. Chemically,mafic rocks can be enriched in iron, magnesium, and calcium.

In embodiments of systems and methods, produced hydrogen can beconverted reversibly to ammonia for safe storage and transportation in areduced volume. The versatility of the present carbon capture andstorage (“CCS”) systems and methods also allows CO₂ from other sourcessuch as refining, power production, and desalinization to be immobilizedeconomically, for example in basaltic rock.

To increase the efficiency of synergistic H₂ production with CO₂removal, H₂ production occurs preceding an alternative CCS process inwhich CO₂ is injected into natural geological sinks comprised ofreactive basaltic and ultramafic lithologies, where it rapidly reacts toform stable mineral phases, such as precipitated carbonates. Carbonstorage in basalts (“CSB”) consumes significantly less energy than otherCCS systems and processes, has advantageously high tolerance to acid gasimpurities (i.e., H₂S), does not require deep wells, such as those 850 mdeep or deeper, and does not require long-term reservoir monitoring.

Storage of CO₂ in basaltic and ultramafic rocks is unique compared toconventional CCS, because it relies in part on rapidly proceedingchemical reactions which convert CO₂ gas to solids, rather than relyingon physical storage of CO₂ itself over time. Economic estimatesdemonstrate the cost for one metric ton of CO₂ captured by presentlydisclosed systems and methods is about two to four times lower ascompared to conventional CCS.

In some embodiments, low purity CO₂ gas is dissolved in water prior toor during injection into a basalt-containing reservoir, and this avoidsdifficulties including compressing and maintaining CO₂ in a liquidstate. Having CO₂ dissolved in an aqueous phase helps avoid the need fordrilling deep disposal wells deeper than about 850 m below the surface,as is required in conventional CCS. In other words, significantly lowerpressures are needed to keep sufficient quantities of CO₂ dissolved inwater, and injection zones can be as shallow as 350 vertical metersbelow surface for embodiments of the present disclosure.

Rapid immobilization of CO₂ as solid, stable carbonate minerals not onlyensures permanent removal of CO₂ from the environment, but alsoprecludes the need for sophisticated monitoring programs needed atconventional CCS sites. Extreme tolerance of the present technology tothe presence of up to about 40 mol % of other water soluble waste gasessuch as H₂S, which like CO₂ is rapidly and substantially completelymineralized in basalts and ultramafics, also has important efficiencyimplications.

CSB negates the need for expensive and energy consuming steps to removesulfur/H₂S impurities from CO₂ and other gases produced during H₂production. Another important advantage is that in contrast to liquidCO₂, which is less dense than reservoir water and thus buoyant, CO₂-richwater has higher density than ambient groundwater. Consequently, wheninjected CO₂-rich water will sink in the reservoir rather than moveupwards, which eliminates the need of a caprock—a critically importantgeological feature of all conventional CCS reservoirs. In embodiments ofthe present disclosure, injection and storage of CO₂ in basalts andmafics has no impact on the quality of groundwater residing in thoselithologies. This is particularly important when such aquifers are usedto supply drinking water or water for other purposes.

Therefore, disclosed here is a method for producing hydrogensubstantially without greenhouse gas emissions, the method includingproducing a product gas comprising hydrogen and carbon dioxide from ahydrocarbon fuel source; separating hydrogen from the product gas tocreate a hydrogen product stream and a byproduct stream; injecting thebyproduct stream into a reservoir containing mafic rock; and allowingcomponents of the byproduct stream to react in situ with components ofthe mafic rock to precipitate and store components of the byproductstream in the reservoir.

In some embodiments, the mafic rock comprises basaltic rock. In otherembodiments, before the step of injecting the byproduct stream into thereservoir, the byproduct stream is further treated to separate andpurify CO₂ from other components to increase CO₂ concentration of thebyproduct stream for injection into the reservoir. Still otherembodiments of the method further comprise the step of liquefying CO₂ inthe byproduct stream for injection into the reservoir. In someembodiments, the method includes the step of mixing the byproduct streamwith water, the byproduct stream comprising H₂S. In some embodiments,the method includes the step of reacting the separated hydrogen withnitrogen to form compressed liquid ammonia. Still other embodimentsinclude the steps of transporting the compressed liquid ammonia andreturning the compressed liquid ammonia to hydrogen and nitrogen viaelectrolysis for use of hydrogen as a hydrogen fuel source.

In still yet other embodiments, the step of producing a product gasincludes steam reforming or partial oxidation. In certain embodiments,the step of allowing components of the byproduct stream to react in situwith components of the mafic rock to precipitate produces precipitatesselected from the group consisting of: calcium carbonates, magnesiumcarbonates, iron carbonates, and combinations thereof. Still in otherembodiments, the reservoir is between about 250 m and about 500 m belowthe surface and is between about 150° C. and about 280° C., or less. Inother embodiments, the reservoir is between about 350 m and about 1,500m below the surface and is less than about 325° C.

Additionally disclosed here is a system for producing hydrogensubstantially without greenhouse gas emissions, the system including ahydrogen production unit with a hydrocarbon fuel inlet operable toproduce a product gas comprising hydrogen and carbon dioxide fromhydrocarbon fuel; a hydrogen separation unit operable to separatehydrogen from the product gas to create a hydrogen product stream and abyproduct stream; and an injection well operable to inject the byproductstream into a reservoir containing mafic rock to allow components of thebyproduct stream to react in situ with components of the mafic rock toprecipitate and store components of the byproduct stream in thereservoir. In some embodiments, the mafic rock comprises basaltic rock.In other embodiments, the system includes a byproduct treatment unit totreat the byproduct stream to separate and purify CO₂ from othercomponents and to increase CO₂ concentration of the byproduct stream forinjection into the reservoir.

Still in other embodiments, the system includes a compressor to liquefyCO₂ in the byproduct stream for injection into the reservoir. In certainembodiments, the system includes a mixing unit to mix the byproductstream with water, the byproduct stream comprising H₂S. Still in otherembodiments, the system includes a reaction unit to react the separatedhydrogen with nitrogen to form compressed liquid ammonia. In certainembodiments, the system includes a transportation unit to transport thecompressed liquid ammonia and return the compressed liquid ammonia tohydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogenfuel source.

Still in other embodiments, the hydrogen production unit includes asteam reformer or partial oxidation reactor. In some embodiments,components of the produced byproduct stream react in situ withcomponents of the mafic rock to precipitate products selected from thegroup consisting of: calcium carbonates, magnesium carbonates, ironcarbonates, and combinations thereof. In certain embodiments, thereservoir is between about 250 m and about 500 m below the surface andis between about 150° C. and about 280° C. Still in other embodiments,the reservoir is between about 350 m and about 1,500 m below the surfaceand is less than about 325° C.

In some embodiments disclosed herein is a method for reducing greenhousegas emissions. The method including producing a waste gas streamcomprising between 0 and 40 vol %, inclusive, carbon dioxide,pre-concentrating the waste gas stream to increase a concentration ofcarbon dioxide, producing a concentrated byproduct stream comprising 40vol % to 75 vol % carbon dioxide, dissolving carbon dioxide contained inthe concentrated byproduct stream in water, producing a dissolvedbyproduct stream and an undissolved byproduct stream, injecting thedissolved byproduct stream or a portion thereof into a reservoircontaining mafic rock, and allowing components of the dissolvedbyproduct stream to react in situ with components of the mafic orultramafic rocks to precipitate and store components of the byproductstream in the reservoir.

In another embodiments disclosed herein is a system for reducinggreenhouse gas emissions. The system including a facility configured toproduce a waste gas stream comprising from 0 vol % to 40 vol % carbondioxide, inclusive, a pre-concentrator configured for increasing aconcentration of carbon dioxide in the waste gas stream, producing aconcentrated byproduct stream, a water dissolution system configured fordissolving the carbon dioxide in water, producing a dissolved byproductstream and an undissolved byproduct stream, and an injection welloperable to inject the dissolved byproduct stream into a reservoircontaining mafic rock to allow components of the concentrated byproductstream to react in situ with components of the mafic or ultramafic rocksto precipitate and store components of the byproduct stream in thereservoir.

In another embodiment disclosed herein is a method for sequestering CO₂.The method including producing a product gas comprising carbon dioxideand one or more selected from the group consisting of H₂S, SO₂, Ar, andN₂ from a hydrocarbon fuel source, pre-concentrating the product gas ina pre-concentrator to increase a concentration of carbon dioxide fromless than 20 vol % to above 40 vol %, producing a concentrated byproductstream, dissolving the concentrated byproduct stream in water, producinga dissolved byproduct stream comprising water, CO₂, and any dissolvedH₂S and/or SO₂; and injecting the dissolved byproduct stream into areservoir containing mafic or ultramafic rocks, and allowing the CO₂ andany H₂S and SO₂ to react in situ with components of the mafic rock toprecipitate and store components of the byproduct stream in thereservoir.

BRIEF DESCRIPTION OF DRAWINGS

These and other features, aspects, and advantages of the presentdisclosure will become better understood with regard to the followingdescriptions, claims, and accompanying drawings. It is to be noted,however, that the drawings illustrate only several embodiments of thedisclosure and are therefore not to be considered limiting of thedisclosure's scope as it can admit to other equally effectiveembodiments.

FIG. 1 shows a schematic flow chart for an example embodiment of asystem for simultaneous H₂ production, H₂ transport, and CO₂sequestration for producing H₂ from hydrocarbons with near zerogreenhouse gas emissions.

FIG. 2 shows a schematic flow chart for an example embodiment of a CO₂sequestration using a pre-concentrator.

DETAILED DESCRIPTION

So that the manner in which the features and advantages of theembodiments of systems and methods of H₂ production from hydrocarbonswith near zero greenhouse gas emissions, as well as others, which willbecome apparent, may be understood in more detail, a more particulardescription of the embodiments of the present disclosure brieflysummarized previously may be had by reference to the embodimentsthereof, which are illustrated in the appended drawings, which form apart of this specification. It is to be noted, however, that thedrawings illustrate only various embodiments of the disclosure and aretherefore not to be considered limiting of the present disclosure'sscope, as it may include other effective embodiments as well.

The production of H₂ from hydrocarbons using technologies such assteam-reforming or partial oxidation/gasification includes three steps.In steam reforming, hydrocarbons, for example methane, are heated in thepresence of H₂O (steam) and catalysts to release raw syngas consistingof hydrogen (H₂), carbon monoxide (CO), small amounts of carbon dioxide(CO₂), and/or other impurities as shown in Equations 1 and 2:

CH₄+H₂O↔CO+3H₂  Eq. 1

and/or

C_(n)H_(m) +nH₂O↔nCO+(n+0.5m)H₂  Eq. 2

The raw syngas is then treated to remove sulfur compounds and/orpurified further. H₂ yield is then maximized by reacting the raw syngaswith H₂O steam in the presence of catalyst to produce H₂ and CO₂according to Equation 3:

CO+H₂O→CO₂+H₂  Eq. 3

This is known as a water-gas shift reaction, hence the product is called“shifted” syngas. In partial oxidation, hydrocarbons are reacted withsmall (non-stoichiometric) amounts of oxygen (O₂) to produce raw syngasconsisting of H₂ and CO according to Equation 4:

CH₄+½O₂→CO+2H₂  Eq. 4

This raw syngas also contains minor amounts of CO₂ and/or nitrogen (N₂,if air was used instead of pure O₂). The raw syngas is then purified,and its H₂ content maximized by the reaction of Equation 3. Thecomposition of an example shifted syngas produced by both processes(steam reforming and partial oxidation) is presented in Table 1:

TABLE 1 Example shifted syngas composition from steam reforming orpartial oxidation. Component H₂ CO CO₂ N₂ O₂ Ar H₂S H₂O Other Mol % 40.91 29.8 2.4 0 0.4 0.01 25.4 0.11

Following water-gas shift, H₂ is purified by separation from CO₂ andother impurities by processes that employ adsorption, absorption, and/ormembrane filtration. One example process is Pressure Swing Adsorption(“PSA”), which uses pressure-dependent selective adsorption propertiesof materials such as activated carbon, silica, and zeolites. Waste orbyproduct CO₂ and other impurities separated from H₂ during PSA are thenvented to the atmosphere. Unfortunately, if a conventional CCS schemewere to be used to sequester CO₂, then the CO₂ must be purified furtherand compressed to a liquid (supercritical) state for transportation andinjection in a deep reservoir. Both steps, however, are avoided (orsimplified significantly) here when CSB is applied instead.

While conventional CCS relies predominantly on physical processes suchas the injection and storage of single phase liquid CO₂ in non-reactiverock reservoirs (e.g., sandstone, limestone), CSB relies on thenaturally occurring chemical reactions between CO₂ and mafic andultramafic rocks to precipitate solid carbonates. Reactions include thefollowing: first CO₂ dissolves in and reacts with water (either or bothwater supplied with CO₂ gas at the surface or water present in situ in amafic reservoir) to form a week carbonic acid as shown in Equations 5-7:

CO₂+H₂O↔H₂CO_(3(aq))  Eq. 5

H₂CO₃↔HCO₃ ⁻+H⁺  Eq. 6

HCO₃ ⁻↔CO₃ ²⁻+H+  Eq. 7

Acidified water dissolves Ca, Fe, and Mg-rich silicate phases (mineralsand/or volcanic glass) which results in the release of divalent metalions in solution according to Equation 8:

(Mg, Fe, Ca)₂SiO₄+4H⁺→2(Mg, Fe, Ca)²⁺+2H₂O+SiO_(2(aq))  Eq. 8

CO₃ ²⁻ formed during the reaction shown in Equation 7 reacts with thedivalent metal cations leading to the precipitation of carbonateminerals as shown in Equation 9:

(Ca, Mg, Fe)²⁺+CO₃ ²⁻→(Ca, Mg, Fe)CO₃   Eq. 9

Geochemical reaction-transport modeling demonstrates that mineral phases(for example calcite, siderite, and magnesite) will remain stable underprevailing subsurface conditions, hence safely removing CO₂ from theatmosphere for hundreds of thousands to millions of years. Othercarbonate minerals include ankerite Ca[Fe, Mg, Mn](CO₃)₂. In addition,CSB has extreme tolerance for other water soluble acid gas impurities(e.g. H₂S, which is also mineralized as sulphides). Such an advantageousquality not only simplifies the process further, eliminating the need toremove those impurities from a gas mixture exiting an H₂ productionprocess, but it also allows for simultaneous sequestering of all otherH₂O soluble gas contaminants capable of forming stable mineral phases byreacting with basalts/ultramafics.

CO₂ dissolution in water for CSB can be achieved by either: a)separately injecting CO₂ and water in the tubing and annular space ofinjector wells and allowing these to mix at or below about a 350 m depthin the wellbore prior to entering the reservoir; or b) dissolving CO₂and water at the surface in a pressurized vessel and then injecting thesolution in a basalt/ultramafic reservoir. While the first methodgenerally applies to pure CO₂ and/or a mixture of CO₂ and other watersoluble acid gases, the latter method is used to effectively separateCO₂ (and other water soluble gases) from insoluble or weekly solubleimpurities, and can therefore be used to process complex flue gasmixtures (e.g. shifted syngas).

Due to certain thermodynamic constraints of CO₂ dissolution in water,both methods require about 27 tons of H₂O per 1 ton of CO₂ sequestered.In areas where water is in short supply, CSB may be done by injectingsupercritical (liquid) CO₂ in basalts or ultramafics; however, thiswould increase energy demands due to the need for liquefying CO₂ viacompression.

The solubility of CO₂ and other waste gases in water is proportional totheir fraction in waste gas mixtures. As a result, water scrubbing ofCO₂ from CO₂-lean mixtures, such as those found in stack emissions frompower generation plants, desalination plants, cement plants, etc., canrender CSB less cost effective. A thermodynamic calculation shows that,at optimal conditions (i.e., 100 vol % CO₂ and freshwater as a carrierfluid), the amount of water needed to dissolve one ton of pure CO₂ at apressure of 35 bar and a temperature of 25° C. is 19 tons (see Table 1).

TABLE 1 quantity of fresh water (in tons) needed to dissolve one ton ofCO₂ at 25° C. as a function of the pressure and fraction (% vol) of CO₂in the gas mixture. CO₂ Contrast of gas (mol percent or approximatelyvolume percent) Pressure, bar 100 80 60 40 20 10 5 2 331.3 414.1 552.2828.2 1656.5 3313.0 6626.0 5 132.5 165.6 220.9 331.3 662.6 1325.2 2650.410 66.3 82.8 110.4 165.6 331.3 662.6 1325.2 15 44.2 55.2 73.6 110.4220.9 441.7 883.5 20 33.1 41.4 55.2 82.8 165.6 331.3 662.6 25 26.5 33.144.2 66.3 132.5 265.0 530.1 30 22.1 27.6 36.8 55.2 110.4 220.9 441.7 3518.9 23.7 31.6 47.3 94.7 189.3 378.6 40 16.6 20.7 27.6 41.4 82.8 165.6331.3 45 14.7 18.4 24.5 36.8 73.6 147.2 294.5 50 13.3 16.6 22.1 33.166.3 132.5 265.0

Water demand, however, will increase significantly if CO₂ is to bescrubbed from complex waste gas mixtures. This is because CO₂ solubilityin water is proportional to its partial pressure (or concentration) inthe mixture. For example, given the same pressure and temperatureconditions (i.e. 35 bar and 25° C.) the amount of water required toscrub one ton of CO₂ from a N₂—CO₂ mixture containing 40 vol % CO₂ willbe 47.3 tons. If the CO₂ concentration in the mixture drops to 10 vol %however, which is the typical CO₂ content of a flue gas stream from aconventional power plant, the quantity of water needed to scrub one tonof CO₂ will be 189.3 tons or greater. Therefore, the water and/or energydemands for scrubbing CO₂ from CO₂-lean gas mixtures is high andpotentially limiting to the applicability of CSB in such cases. Whileconditions of 35 bar and 25° C. are noted above, other scrubbingconditions may also be used, and may vary depending upon the feed gascomposition. For example, pressure and temperature can be as high asthat which CO₂ will turn supercritical.

With respect to the produced H₂, conventionally H₂ is stored andtransported as a liquid at a temperature of about −253° C., whichrequires special double-walled isolated vessels and/or constantrefrigeration. However, reversible chemical conversion of H₂ into liquidammonia (NH₃) allows storage and transportation of H₂ at low pressureand ambient temperatures, at greatly reduced volumes. The reversible H₂to NH₃ storage and transport method is inherently safer andadvantageous, in particular where large volumes of H₂ are to be storedand transported.

Due to high tolerance of CSB to impurities in the CO₂ stream (such asH₂S and other gases), CO₂-rich tail gases from other sources such asrefining, power production, and desalinization could, after limitedtreatment, be either added to the principal waste stream orindependently injected into reactive lithologies for permanentimmobilization and disposal.

Unexpected and surprising advantages of simultaneously producing H₂ fromhydrocarbons while using CSB for permanent CO₂ immobilization in basaltsand ultramafics include significantly lower predicted energy usage andcost due to: lower energy consumption and lower well costs because thereis no requirement to compress and liquefy the CO₂; lower complexity ofoperations due to high tolerance to impurities in the CO₂ stream;simultaneous removal of H₂S along with CO₂ in the reservoirs viaprecipitation as solids; no need for a reservoir caprock; and no needfor sophisticated long-term monitoring programs. There is no need toliquefy CO₂ when it is dissolved in water either at the surface or inthe wellbore, but it would be liquefied if directly injected in thesubsurface as supercritical fluid.

FIG. 1 shows a schematic flow chart for an example embodiment of asystem for simultaneous H₂ production, H₂ transport, and CO₂sequestration for producing H₂ from hydrocarbons with near zerogreenhouse gas emissions. In system 100, a hydrocarbon inlet 102provides a hydrocarbon source, for example natural gas, to a hydrogenproduction system 104. Hydrogen production system 104 might includesteam reforming or partial oxidation, and water-gas shift reactions, forexample as described in Equations 1-4. Production gases exit via outlet106 to a separation unit 108. Separation unit 108 is operable toseparate hydrogen from CO₂ and other byproducts, and can include forexample one or more absorption units, adsorption units, membraneseparation units, or any suitable separation technology for separatingH₂ from CO₂ and other product gases, such as for example acid gas

CO₂ and additional gases, such as acid gases, exit separation unit 108via outlet 110 and can optionally proceed to a further CO₂ purificationand liquidification unit 112, but need not to. In the case of furtherCO₂ purification and liquidification unit 112, liquefied CO₂ is injectedinto basaltic formation 116 via injection well 114 to form solidprecipitated metal carbonates per Equations 5-9. Without optionalfurther CO₂ purification and liquidification unit 112, CO₂ andadditional gases such as acid gases exit separation unit 108 via outlet110 and proceed directly into basaltic formation 116 via injection well114 to form solid precipitated metal carbonates per Equations 5-9. CO₂can be mixed with water as a gas at the surface or in situ in basalticformation 116, or both. Solid carbonate nodules form in vugs and veinsin basalt around injection wells and extending outwardly from theinjection wells.

Rates of basalt dissolution and mineral carbonation reactions canincrease with increasing temperature, and thus higher temperaturebasaltic reservoirs may be advantageous, while deep reservoirs beyondabout 350 m are not required because high pressures are not required tokeep CO₂ in a pressurized or liquid state. An example suitable reservoirtemperature is about 185° C., or for example between about 150° C. andabout 280° C. As explained, injected CO₂, either by itself or with othergases, creates an acidic environment with water near the injection well,such as injection well 114. Near injection well 114, the acidic fluidsremain undersaturated with respect to basaltic minerals and volcanicglass.

Undersaturation and acidity leads to dissolution of host rock basalts inthe vicinity of injection wells, such as injection well 114.Mineralization then mostly occurs at a distance away from the injectionwell (which allows continuous injection of CO₂ in a reservoir such asbasaltic formation 116), after heat exchange and sufficient dissolutionof host basaltic rock neutralizes the acidic water and saturates theformation water with respect to carbonate and sulfur minerals.

Hydrogen exits separation unit 108 at outlet stream 118 to proceed toreaction unit 120 where hydrogen is reacted with nitrogen to formammonia (NH₃). Ammonia exits reaction unit 120 at outlet 122 for reducedvolume transport of H₂ as NH₃. Reaction unit 120 can include apressurized multistage ammonia production system (PMAPS) to produceammonia in a pressurized liquid phase. Pressurized liquid NH₃ can betransported by a pressurized tanker truck, and using an NH₃electrolyzer, NH₃ can be reversibly returned to N₂ and H₂ whereverhydrogen is required.

The above was found to be effective for processes that produce H₂ andhave a high concentrations of CO₂ in the byproduct streams (40 vol %+),such as may be produced via gasification and other processes noted. Theprocessing of the hydrogen-containing streams in adsorptive and otherprocesses focused on recovering the hydrogen permits CSB of the CO₂byproduct, as described in various embodiments above.

However, it has also been found that CO₂ may be effectively andefficiently sequestered from other various product and waste streams,including CO₂-lean streams from facility is selected from the groupconsisting of a power production facility, a desalination plant, arefinery, a chemical production plant, an ore smelting plant, a cementproduction plant, a logging plant, a landfill, a fertilizer productionplant, and other industrial facilities, among others. In someembodiments, the CO₂-lean stream may have other gas components which mayalso be handled by the process and system of one or more embodimentsdisclosed herein. For example, the CO₂-lean stream may have N₂, Ar, SO₂,H₂S, or other inert gases or acid gases. Inert gases may ultimately bevented to atmosphere while CO₂ and other acid gases may ultimately besequestered. The CO₂-lean streams that may be processed according toembodiments herein may have a CO₂ concentration of less than 40 vol %.Embodiments herein may also effectively sequester CO₂ from very leanstreams, such as a flue gas or other waste streams having, for example,from 4 vol % to 12 vol % CO₂. While it is not routine, arguably not evencontemplated in the art to sequester CO₂ from such lean streams, byusing water solubility trapping for storage in basalts or other reactiverocks, embodiments herein may be used to initially enhance the CO₂concentration of the waste stream and then effectively dissolve the CO₂and other acid gases in water, and providing the mixture of CO₂ andwater for injection into a well.

The CO₂ concentration of the CO₂-lean stream may be less than 5,7, 10,15, 20, 25 or 30 vol % before pre-concentration, and may be concentratedto above 35, 40, 45, 50, 55, 60, or 70 vol %, where any lower limit maybe combined with any appropriate upper limit. While waste streams mayhave a broad range of CO₂ concentrations, the CSB has been found toeffective where the waste stream is initially pre-concentrated to a CO₂concentration above 35, 40, or 45 vol %. Additionally, gas streamshaving higher initial concentrations than those listed above may bepre-concentrated according to embodiments herein, such as where there isa positive net economic impact, such as in reduction of water usage,energy usage, and/or capital or operating expenses (CAPEX and OPEX,respectively) for the facility.

Embodiments herein may result in a concentrated CO₂ stream having a CO₂concentration of greater than 40 vol %, as noted above, including highpurity CO₂ streams, such as greater than 90 vol %, for example. Someembodiments herein may provide a concentrated CO₂ stream having amoderate purity of CO₂, such as less than 85 vol %, less than 80 vol %,less than 75 vol % or less than 70 vol %. It has been found thateffective sequestration may be achieved through pre-conditioning to fita wide range of CO₂ concentrations, depending on water and energyavailability, as well CAPEX and OPEX of the facility. The ability toprocess lower purity CO₂ streams according to embodiments herein mayprovide significant advantages in processing options, costs, and otherconventional factors, especially as compared to other carbonsequestration processes that require greater than 99 vol % CO₂ to becost effective.

Since the relationship between the CO₂ partial pressure and itssolubility in water is non-linear, a relatively moderate increase of theconcentration of CO₂ in the flue gas can improve significantly the costeffectiveness of the CSB dissolution method by significantly reducingwater demand. For example, an increase of the concentration of CO₂ from10 to 40 vol % will reduce the quantity of water needed by a factor of4, and if CO₂ concentration is increased to 60 vol %, water demand willdrop to about one sixth of the volume needed to trap CO₂ from a 10 vol %mixture. This significant reduction of fluid volume will not only reducethe demand of energy for pumping and compression but also the number ofdisposal wells.

Accordingly, it is further envisioned that CSB as described herein canapply to other processes and may be implemented at any industrialfacility (e.g., power plants, refineries, water desalination plants,cement plants, smelters, etc.) where CSB can be utilized toreduce/eliminate the facilities' CO₂ (and H₂S) emissions, even infacilities where the CO₂ concentration in the waste byproduct stream islow and conventional sequestration by CSB is not practical. This isconditional upon the proximity of said facilities to accumulations ofreactive rocks, such a basalt, of sufficient volume, thickness, andwater saturation volume, to allow the use of CSB for CO₂ sequestration.

In such embodiments, it is envisioned to apply a separate CO₂ (acid gas)pre-concentration step. The purpose of this step is to increase CO₂concentrations to the medium-high ranges, rather than to the near 100vol % CO₂ concentrations required for conventional CCS. Because the CO₂water scrubbing mechanism may also be intended to sequester acid sulphurgases (e.g., H₂S), the CO₂ concentration method does not need to removesuch impurities. This step can employ any conventional method ortechnology for pre-concentrating CO₂, such as, but not limited to,absorption based methods using monoethanolamine (MEA) solutions,adsorption based methods such as Pressure Swing Adsorption (PSA),metal-organic framework (MOF), membrane gas separation, and chemicallooping combustion, among other. Further, multiple of the same unit maybe used in series, multiple different units may be used in series, andparallel pre-concentrating steps may be used. For example, two PSAs maybe used in series, with two series of PSAs being used in parallel.Additionally, two PSAs may be used with an MEA, MOF, membrane gasseparation, or chemical looping combustion unit either before, after, orin between the PSAs.

Such processes may increase the CO₂ concentration by removing one ormore of water vapor, nitrogen, nitrogen oxide, CO, etc. In otherembodiments, such processes may increase the CO₂ and H₂S concentrationby removing one or more of water vapor, nitrogen, nitrogen oxide, CO,etc.

The increase in CO₂ concentration from 7-10 vol %, as would typically befound in low concentration byproduct streams, to above 40 vol % can beachieved by introducing a CO₂ (or a CO₂ and H₂S) concentration unit tothe water scrubbing process at a CSB facility. This may reduce thescrubbing facility's operational costs (OPEX) by reducing the volume ofwaste gas to be processed, the volume of water needed to dissolve/scrubCO₂ and consequently the energy needed for pumping and compressing boththe water and the gas. That in turn may also reduce capital expenditurecosts (CAPEX) by reducing the size of the scrubber facility, thediameter of the delivery pipeline(s) as well as the number of disposalwells needed.

FIG. 2 shows a schematic of the system disclosed herein in which a CO₂pre-concentrator is used to prepare a CO₂ stream for water scrubbing anddisposal in reactive rocks. The CO₂ stream may be a CO₂-lean waste gasstream from a power production facility, a desalination plant, arefinery, a chemical production plant, an ore smelting plant, a cementproduction plant, a logging plant, a landfill, a fertilizer productionplant, or other industrial facilities. A CO₂-lean stream 200 from anysuitable source may be fed to the CO₂ pre-concentrator 202, which mayproduce a concentrated CO₂ stream 204 and an insoluble gas stream 218 a.The concentrated CO₂ stream may then be fed to a compressor 206 toincrease the pressure of the concentrated CO₂ stream, producing apressurized CO₂ stream 208. The concentrated CO₂ stream 208 may then befed to a CO₂ scrubbing unit, where the gases are contacted with water todissolve the CO₂. CO₂ scrubbing unit 210 may also be operable toseparate N₂, Ar, and other insoluble or inert gases from CO₂ and otheracid gases, such as hydrogen sulfide (H₂S) and/or sulfur dioxide (SO₂),while dissolving CO₂ and other acid gases, such as H₂S, in water. Awater inlet 212 is fed to a water pump 214 with the pressurized water216 being used as the scrubbing medium. The insoluble gases (orundissolved byproducts) are collected in outlet 218 b, and may be sentto further purification, utilization, vented to atmosphere, or acombination thereof, as necessary.

CO₂ and additional gases, such as acid gases, are dissolved in the waterand exit scrubbing unit 210 via outlet 220. The CO₂-water mixture maythen be fed to a pump 222 and injected via flow line 224 into basalticformation 226, such as through an injection well, to form solidprecipitated metal carbonates per Equations 5-9. Solid carbonate orsulfide nodules form in basalt around injection wells and extendoutwardly from the injection wells.

As described above, embodiments herein may provide for the efficientsequestration of carbon from both CO₂-lean waste streams and synergistichydrogen production.

The singular forms “a,” “an,” and “the” include plural referents, unlessthe context clearly dictates otherwise.

In the drawings and specification, there have been disclosed embodimentsof systems and methods for reducing or eliminating greenhouse gasemissions, and although specific terms are employed, the terms are usedin a descriptive sense only and not for purposes of limitation. Theembodiments of the present disclosure have been described inconsiderable detail with specific reference to these illustratedembodiments. It will be apparent, however, that various modificationsand changes can be made within the spirit and scope of the disclosure asdescribed in the foregoing specification, and such modifications andchanges are to be considered equivalents and part of this disclosure.

1.-11. (canceled)
 12. A system for reducing greenhouse gas emissions,the system comprising: a facility configured to produce a waste gasstream comprising from greater than 0 vol % to less than 40 vol % carbondioxide; a pre-concentrator configured for increasing a concentration ofcarbon dioxide in the waste gas stream, producing a concentratedbyproduct stream; a water dissolution system configured for dissolvingthe carbon dioxide in water, producing a dissolved byproduct stream andan undissolved byproduct stream; and an injection well operable toinject the dissolved byproduct stream into a reservoir containing maficor ultramafic rock to allow components of the concentrated byproductstream to react in situ with components of the mafic rock to precipitateand store components of the byproduct stream in the reservoir.
 13. Thesystem according to claim 12, where the mafic rock comprises a basalticrock or a silicate rock reactive with CO₂.
 14. The system according toclaim 12, wherein the pre-concentrator is one or more selected from thegroup consisting of a monoethanolamine (MEA) solution absorption unit, apressure swing adsorption (PSA) unit, a metal-organic framework (MOF)unit, a membrane gas separation unit, and a chemical looping combustionunit.
 15. The system according to claim 12, wherein the pre-concentratoris configured to increase the CO₂ concentration from less than 10 vol %to above 40 vol %.
 16. The system according to claim 12, where thefacility is selected from the group consisting of a power productionfacility, a desalination plant, a refinery, a chemical production plant,an ore smelting plant, a cement production plant, a logging plant, alandfill, a fertilizer production plant, and other industrialfacilities.
 17. The system according to claim 12, where the reservoir isbetween about 250 m and about 500 m below the surface and is betweenabout 150° C. and about 280° C.
 18. The system according to claim 12,where the reservoir is between about 350 m and about 1,500 m below thesurface and is less than about 325° C. 19.-21. (canceled)